A Day in the Life of Transmission Congestion


A forecast for California on Aug. 16, 2006

Fortnightly Magazine - May 2005

Transmission congestion affects both the cost and the efficiency of the electric power grid. Traditionally, transmission congestion has been managed as an engineering or contractual matter, through physical management of the grid or contractual management of "contract paths" for delivering electricity. The use of locational marginal pricing (LMP)—a market-based approach that sends price signals to transmission generators and load-serving entities—uses the grid to encourage the most efficient use of the transmission system.

Global Energy's Market Analytics LMP along with PowerWorld Corp.'s OPF Simulator and Energy Visual's graphical interface solution provides a richly textured visual representation of Global Energy's forecast of transmission congestion in California for Aug. 16, 2006.

LMP Is About Managing Transmission Congestion

By calculating locational marginal prices and plotting them graphically using the Global Energy and PowerWorld software, it is possible to provide a complete zonal to nodal analysis of transmission congestion and the locational marginal price implications of transactions on the grid.

The locational marginal price is the incremental value (marginal cost) of an additional megawatt of energy injected at a particular location, taking into account both generation marginal cost and the physical aspects of the transmission system.

LMP provides better transmission congestion management than the physical contract path approach historically used because it:

  • Involves less command and control, and efficiently assigns congestion costs to cost causer;
  • Efficiently delivers lowest-cost electricity while respecting physical limitations of the system;
  • Relieves congestion and promotes efficient investment providing appropriate price signals;
  • Aligns participant financial incentives with system operator dispatch instructions for reliable operations; and
  • Enables transmission system operation closer to operational limits, reducing costs and increasing supply when the transmission system is constrained.
Transmission congestion analysis as simulated for Aug. 16, 2006, 2 p.m.

Substantial implications to market participants in the use of LMP include:

  • Lessens volatility and altered risk-management strategies for market participants;
  • Requires day-ahead, hour-ahead energy and ancillary services bids;
  • Links price volatility to locational factors, again creating winners and losers;
  • Considers what is monetized as a contingency matters in the LMP calculation;
  • Helps understand both the intrinsic and extrinsic value of congestion revenue rights to fine-tuning bid strategies (bid, self-schedule);
  • Realizes grandfathered financial transmission rights (FTR) favor historical generators at the expense of merchants; and
  • Acknowledges resource adequacy requirements can be fundamentally altered by LMP.

The following figures track the expected congestion on Aug. 16, 2006, and were simulated assessing the transmission congestion and resulting LMP implications as transactions take place to meet normal business needs of electric users. A discussion of how LMPs are calculated and a sample of LMP results is presented.

How Global Energy Calculates LMP

Using the Global Energy and Market Analytics solution, a simulation is developed of desired hourly dispatch of generators where intra-zonal congestion is not considered.

The hourly dispatch and commitment data, along with bid curves of the units, are passed to the OPF model and an accompanying detailed transmission network model. The OPF simulation uses the initial Market Analytics zonal solution and cost-and-performance characteristics of generators, combined with a detailed electrical model of the entire transmission network-including important constraints associated with the electrical network-to minimize power costs subject to generator bids or costs.

Figure 1 - Example Of California Hourly Load Requirements, In-State Generation Dispatch, And Aggregated LMP

The OPF simulation tests for congestion and, if present, optimally redispatches generator units to relieve this congestion. The OPF model will calculate and report bus level prices and other operational data. The Market Analytics LMP platform provides a complete solution to calculating nodal prices and allows an assessment of the impact of nodal prices to each market participant's asset portfolio.

The need for location-specific price information is driven by regional transmission organizations that have adopted LMP market structures, as well as for market participants in regions that have yet to adopt nodal pricing but need to assess locational impacts. Moreover, the use of LMPs as part of a congestion management system is favorably viewed by FERC for its ability to convey appropriate price signals to market participants. It creates the need for market participants to forecast nodal prices to assess generation or transmission system improvements, and to assess the value of financial transmission rights (FTR) in mitigating congestion exposure.

LMPs capture the cost of supplying the next megawatt of load at a specific location, and are calculated using a security-constrained unit commitment dispatch model that goes beyond security constraints typically included in zonal models—such as operating reserves, unplanned outages at generating facilities, and transportation-like representation of key regional transmission paths—to introduce additional constraints tied to a detailed description of the transmission network. These include transmission links and interface limits, and complex operating schedules tied to multiple interfaces.

To illustrate the breadth of information associated with nodal analysis, this analysis considers one week from a simulation of the California markets. An aggregated view of the California market is shown in Figure 1. Since California is the net importer of power in general, and in this week in particular, hourly generation within California is less than hourly load requirements. The balance of energy is scheduled over California's extensive interstate transmission system to deliver power from out of state generators. Figure 1 also shows an aggregated view of prices based on the underlying bus price at each node in the transmission network.

Figure 2 shows the distribution in nodal prices for the peak hour, underlying the nodal prices shown in Figure 1. The figure also shows that wide distribution in bus prices develop due to locational differences inside California. These locational differences are driven by congestion. Figure 2 reveals prices much lower and much higher than the statewide average price. Indeed, it is the locational price signal that is intended to provide market participants better information to use in managing operational and investment-related decisions affecting their asset portfolio.

It is clear from this figure that there are winners and losers, depending on location and whether one is injecting power into the grid (i.e., a generator) or removing power from it (i.e., a load-serving entity). It is also clear that even in one utility's boundary, the variance in nodal prices can be quite high.

Figure 3 illustrates nodal prices at each bus using a price contour map. Different colors are assigned different price ranges. In this figure, blue signifies an area where nodal prices are $10/MWh or less and red signifies prices $50/MWh or more. The legend in Figure 3 provides the range of nodal prices assigned to each color. The four price snapshots assist in visualizing nodal prices throughout one day in August 2006.

  • 1 a.m.: No congestion is present. The figure shows nodal prices at the beginning of the day (1 AM) at a homogenous low price. In this hour, no congestion is present. The green areas represent a transmission region where no bus pricing information is available.
  • 7 a.m.: Congestion is present. Higher prices begin to develop in Northern California, while Southern California prices increase—albeit at a lower level—and a generation pocket in the Monterey, Calif., area results in much lower prices than other areas in California.
  • 2 p.m.: Nodal prices increase throughout California; congestion remains. Color-differentiated congestion is present throughout the transmission network since the red shaded areas only signify higher prices and do not differentiate the congestion present within the red shaded areas.
  • 12 p.m.: Nodal prices decrease throughout California. While congestion still remains, as evidenced by pricing in Northern California being higher than Southern California, nodal prices have decreased significantly from their peak-period prices.


Figure 2 - LMP Price Distribution Aug. 16, 2006 3:00 PM Simulation